Viscosity frequently limits the rate crude oil can be produced from a well. For example, in wells that are pumped by a sucker rod string, viscous drag by the crude oil on the string slows its free fall by gravity on the downstroke. On the upstroke, this drag also slows the string, decreases oil flow through the production tubing, and increases the power required to raise oil and rod string. In some instances where the oil is highly viscous, such as the Boscan field in Venezuela, the strength of the sucker rods limits the depth at which the pump can be operated. Alternatively, hydraulic pumps can be placed at the bottom of the well, but they must still overcome the high viscous drag that requires high power oil pressures and high pump horsepower.
The downhole pump usually provides the pressure required to pump the produced oil from the wellhead to surface gathering tanks. Where viscosity is high, this may require the use of extra strength wellhead equipment (packings, gaskets, heavy walled pipes and the like) to withstand the pressures required to move such viscous oil from wellhead to storage tank.
It has been proposed heretofore to reduce the viscosity of heavy crude oils prior to pumping by introducing low viscosity crude oils, white oil, kerosene or the like into the well bore to dilute or thin the produced crude. In rod pumped wells, it is common to surround the sucker rod string with an extra tubing. Low viscosity oil is pumped down this tubing so that the string is surrounded by lower viscosity oil. This added light oil then mixes with the viscous crude near the traveling valve of the pump to lighten and thin the column of crude oil being pumped from the well through the annulus formed by the inner and the production tubings of the well. Alternatively, low viscosity oil can be pumped down hollow sucker rods and the diluted crude oil produced through the annulus between the hollow rod string and the tubing.
The resulting produced crude has reduced viscosity and is more economically transported; however, these low viscosity diluents are expensive and not always available and have to be reclaimed from the diluted crude.
Another method of reducing the viscosity of the produced heavy crude is by thermal methods, that is, producing them at elevated temperatures. Thermal recovery pertains to oil recovery processes in which heat plays a principal role. The most widely used thermal techniques are hot fluids such as steam, water, or gas and cyclic operations such as steam soaking. Because of the strong temperature dependence of oil viscosity, these thermal methods find greatest applicatiomn in the recovery of extremely viscous, low API gravity crudes, for which the usual displacement method such as waterflooding are unfruitful.
Cyclic steam injection (also called huff and puff steam stimulation) is the most commonly applied thermal recovery process. Steam is injected directed into the reservoir through the production wells to heat the surrounding area. The condensation and cooling of the steam heats the reservoir rock and oil, reducing the oil viscosity and thus increasing production rates. After two or three weeks, the steam injection is stopped and the heated oil is produced from these same wells. After the hot oil production has ended, a new cycle may be initiated. The time period of the cycles is on the order of six to twelve weeks or longer. These reservoirs are usually shallow and producing wells are drilled on very close spacing because the heat does not penetrate far from the wells.
The value of the process lies not so much in improving the ultimate recovery as in increasing the producing rate and yielding a response that is almost immediate upon cessation of steam injection. The primary benefits of the process are the reduction of oil viscosity near the well and the cleaning of the well bore.
Steam drive (also referred to as steam flooding or steam displacement) involves the injection of steam into a group of outlying wells to push oil toward the production wells. In this process the heat is pushed into the perimeters of the reservoir to displace oil and reduce viscosity. To ensure high rates of production at the wellhead, steam flooding projects are typically conducted jointly with cyclic steam injection in the production wells.
The steam-saturated zone, in the reservoir whose temperature is approximately that of the injected steam, moves oil to the production well by steam distillation of the oil, solvent extraction, and a gas drive. As the steam cools and condenses, a zone of hot water is formed which floods the formation. Oil recovery efficiency ranges from 35 to 50% of the reservoir oil in place, depending on oil and reservoir characteristics.
Over twenty-five years ago, the first commercial thermal recovery operations involving steam were started. The center of this activity in the United States was California, and many of these operations continue today. Cyclic steam (or steam soak) was the technique of preference in the ealy days because it stimulated here-to-fore wells of very low productivity. Steam drive (or steam displacement), on a sustained basis, did not begin until the early 1960's, when cyclic steam production began to decline (Matthews, C. S., "Steamflooding", Trans. SPE, Vol 275, Pg 465, 1983.).
In California, there are now more than 350,000 barrels per day of heavy viscous oil being produced as the result of steam injection (Brigham, W. E., "Thermal Oil Recovery in 1987", Second Annual International Enhanced Oil Recovery Conference, June, 1987, Anaheim, Calif. A portion of this is due to steam stimulation (cyclic steam), but the majority comes from steam displacement (steam drive). As these projects have matured, problems began to arise. For example, in steam drive fields the steam eventually "breaks-through" or "channels" to a producing well, and the sweep efficiency declines. Also, there is a continuing problem of moving heavy viscous oil to the producing wells.
The "channeling problem" has been studied by various investigators, and it is believed that this problem can be reduced by the use of foaming agents. The polymeric foaming agents have been evaluated in the laboratory and appear to be useful in minimizing channeling (Navratil, M., Sovak, M., and Mitchell, M. S., "Formation Blocking Agents: Applicability in Water and Steam-Flooding", 58th Annual SPE Conference, San Francisco, Calif., October 1983). However, only a limited number of field tests have been reported as of this date (Doscher, T. M., Kuuskrua, V. A., Hammershaimb, E. C., "Analysis of Five field Tests of Steamdrive Additives", 58th Annual SPE Conference, San Francisco, Calif., October 1983).
Another approach to increasing recovery during steam flooding is the use of surfactants. In one field test, a surfactant which is referred to as a "thin film spreading agent" was used, and the results were encouraging in three of the four wells under test (Adkins, J. D., "Field Results of Adding Surfactant to Cyclic Steam Wells" 58th Annual SPE Conference, San Francisco, Calif. October 1983). In still another field test, an additive containing sodium metasilicate was used during cyclic steam injection (Mbaba, P. E, Caballero, E. P., "Field Application of an Additive Containing Sodium Metasilicate During Steam Stimulation", 58th Annual SPE Conference, San Fransciso, Calif., October 1983).
Although many of the above cited materials have shown some encouraging results, none have been universally accepted as a means of increasing oil recovery during steam stimulation or steam displacement.